Process for capturing acid gases

ABSTRACT

An absorption column  1  for separating CO 2  and a second acid gas from a gas stream, the column comprising a first and second section ( 4, 5 ) for the absorption of CO 2  and the second acid gas; a solvent inlet in the second section for the addition of liquid stream  3  including an absorbent liquid for CO 2  and the second acid gas; a gas inlet ( 21 ) in the first section for the addition of a gas stream ( 2 ) containing CO 2  and the second acid gas; a gas outlet ( 15 ) in the second section of the column; a first solvent outlet ( 22 ) for the removal of at least a portion of the solvent ( 6 ) from the second section of the column and a second solvent outlet ( 23 ) for solvent stream ( 11 ) from the first section of the column; and a liquid flow distributor arrangement ( 8 ) to allow a portion of the solvent to flow from the second section of the column to the first section. A method of operating the apparatus and method of solvent extraction is also disclosed.

FIELD OF THE INVENTION

This invention relates to the capture of CO₂ and at least one otheracidic gas from gas streams by reactive chemical absorption. Inparticular, the invention relates to a process and apparatus whichallows both CO₂ and at least one other acidic gas to be captured using asingle solvent stream in a single absorber column.

BACKGROUND OF THE INVENTION

While the invention will be described with reference to CO₂ and SO₂, itmay be equally applicable to gas streams containing CO₂ and othersulfurous acid gases such as H₂S, or other acidic gases which formstronger acids than CO₂ such as HF, HCl and NO₂.

There is growing pressure for stationary producers of greenhouse gasesto dramatically reduce their atmospheric emissions. Of particularconcern is the emission of carbon dioxide (CO₂) into the atmosphere. Onemethod of reducing atmospheric CO₂ emissions is through its capture at apoint source and subsequent storage in geological or other reservoirs.

The process for capturing CO₂ from power station and other combustiondevice flue gases is termed post combustion capture (PCC). In postcombustion capture, the CO₂ in flue gas is first separated from nitrogenand residual oxygen using a suitable solvent in an absorber. The solventis usually an aqueous basic mixture containing components undergoing achemical reaction with acid gases such as CO₂. It might contain amines(e.g. alkanolamines, ammonia, alkylamines) and/or inorganic salts (e.g.carbonate or phosphate). The CO₂ is subsequently removed from thesolvent in a process called stripping (or regeneration), thus allowingthe solvent to be reused. The stripped CO₂ is liquefied by compressionand cooling, with appropriate drying steps to prevent hydrate formation.PCC in this form is applicable to a variety of stationary CO₂ sourcesincluding power stations, steel plants, cement kilns, calciners andsmelters.

When CO₂ is absorbed into an aqueous solution a number of reactions canoccur. They are shown by the following equations where (1) is hydrationof gaseous CO₂, (2) is the reaction of CO₂ with water to form carbonicacid, (3) is the reaction of CO₂ with hydroxide to form bicarbonate and(4) and (5) are the carbonic acid-bicarbonate-carbonate acid-baseequilbria.

If an amine, or multiple amines, are present in solution a number ofadditional reactions may occur. If the amine is a sterically freeprimary or secondary amine such as monoethanolamine (MEA) ordiethanolamine (DEA) the following reactions can occur between CO₂ andeach amine. Equation (6) is the formation of a carbamate species via anitrogen-carbon bond formation between the amine and CO₂. This isgenerally the kinetically fastest reaction of those that occur with CO₂.Equation (7) is the amine acid-base equilibrium. For polyamines thereactions of equation (6) and (7) may occur for each nitrogen. Forsterically hindered and tertiary amines only the acid-base equilibriumof equation (7) occurs.

Combustion devices that utilise fuel containing sulfur (such as coal andoil) also produce sulfur dioxide (SO₂) as a combustion product in theirflue gas. In untreated flue gas from coal fired power stations, thelargest source of CO₂ emissions globally, the SO₂ content varies between100-5000 ppmv. In other off-gases such as those of smelters, theSO₂-content might reach levels in excess of 10%. SO₂ emissions have longbeen recognised as the primary cause of acid rain and the subsequentenvironmental degradation that results. As a consequence flue gasdesulfurisation (FGD) technology was developed to capture the SO₂ fromcombustion flue gas prior to its emission to the atmosphere. FGD isutilised primarily in the USA, Europe, Japan and increasingly in China.After FGD the sulfur content is usually reduced to levels between 10 and100 ppm, depending on the particular FGD technology used, the originalsulfur content in the coal and the legislative requirements for sulfurcontent in the remaining flue gases.

As SO₂ and CO₂ are both acid gases, with SO₂ being a significantlystronger acid, the presence of SO₂ in flue gas degrades the performanceof CO₂ capture. When SO₂ is absorbed into an aqueous solution analogousreactions occur to those for CO₂. Equation (8) is hydration of gaseousSO₂, equation (9) is the formation of sulfurous acid, equation (10) isthe formation of bisulfate and equations (11) and (12) are the sulfurousacid-bisulfite-sulfite acid-base equilibria. The oxidation of sulfite tosulfate, which may occur in the presence of molecular oxygen, has notbeen included as its small reaction rate means it has no impact upon theinvention described herein.

However, unlike CO₂, SO₂ does not react directly with amines present insolution. The other significant difference is that SO₂ is a muchstronger acid and is absorbed much more rapidly than CO₂. The pK_(a)'sof bisulfite and sulfurous acid are 7.17 and 1.85 respectively at 25°C., compared to 10.3 and 3.34 for bicarbonate and carbonic acid. Alsothe reaction rate constant of SO₂ and water is almost two orders ofmagnitude larger than the largest known rate constant for CO₂ reactingwith an amine, which is its reaction with piperazine (PZ). Consideringwater is present at a much larger concentration than any amine theoverall rate of reaction for SO₂ will be greater still.

The physical solubility of SO₂ in an aqueous solution is over an orderof magnitude larger than CO₂. The Henry coefficient at 25° C. (definedas the gas phase partial pressure over the liquid phase concentration ofthe gas,

$ {H_{i} = \frac{P_{i}}{c_{i}}} )$

for SO₂ is 82.46 KPa.L.mol⁻¹ while for CO₂ it is 3265 kPa.L.mol⁻¹. Theyboth share similar diffusion coefficients. The combination of greaterphysical solubility, faster reaction rate and greater acidity means thatwhen both CO₂ and SO₂ are simultaneously present in flue gas SO₂ isabsorbed preferentially to and more rapidly than CO₂. This is the caseeven if the gas phase concentration of SO₂ is significantly lower thanCO₂.

Modelling of CO₂ and SO₂ absorption into a falling thin film of aqueousMEA has been completed to illustrate this selectivity. A falling thinfilm is the type of hydrodynamic environment found in packed columnscommonly used for CO₂ capture applications where a liquid film fallsunder gravity over packing material and is counter-currently contactedwith a gas stream. Chemical diffusion and reaction in a thin film hasbeen modelled by solving the appropriate partial differential equationsand simultaneous equations needed to describe the reactions betweenaqueous MEA, CO₂ and SO₂. The method is described in detail in G. Puxtyand R. Rowland, Env. Sci. Technol. 2011, 45, 2398-2405. FIG. 1 is a plotshowing the impact of gas phase SO₂ concentration on the CO₂ absorptionflux into a thin film of 30% w/w aqueous MEA at 40° C. as determined bymodelling (filled markers). The gas phase CO₂ concentration was 10 kPaand exposed to the film for 0.3 seconds, the liquid CO₂ loading (molCO₂/mol MEA) was varied between 0-0.5 and the gas phase SO₂concentration between 0-800 ppmv. The conditions for the modelling werechosen to be similar to those used for experimental validation of thepatent concept, as described in the next paragraph. In all cases as theSO₂ concentration increases the CO₂ absorption flux is very slightlyreduced. This is due to the preferential absorption of SO₂ and theassociated acidification of the solution. This effect is most pronouncedif the solvent is loaded with CO₂, as would be the case in realoperation. Also shown is the SO₂ absorption flux, which is observed toincrease linearly with increasing SO₂ concentration in the gas phase.This indicates that the rate of chemical reaction with SO₂ is so fastthat its absorption flux is entirely controlled by the gas side.

FIG. 2 is a plot of measurements of the impact of gas phase SO₂ on theCO₂ absorption flux into 30% aqueous MEA at 40° C. These measurementswere made using the wetted-wall contactor shown in FIG. 3. FIG. 3 showsa wetted-wall contactor comprising a liquid inlet (301), a liquid outlet(302), a gas inlet (303), and a thin liquid film (304). A detaileddescription of this apparatus is given in G. Puxty, R. Rowland and M.Attalla, Chem. Eng. Sci. 2010, 915-922 and it was used as described withthe following modifications: the addition of SO₂ as a feed gas; use of 2mol.dm⁻³ H₂SO₄ in the saturator; and the addition of an SO₂ gasanalyser. A 1 dm³ min⁻¹ inlet gas stream containing 10 kPa CO₂, 0-800ppmv SO₂ and the remainder N₂ was contacted with at 40° C. with fallingthin liquid film flowing at 121.4 cm³ min⁻¹. The concentration of CO₂and SO₂ in the outlet gas stream was measured using the gas analyser andthe absorption fluxes determined. The liquid CO₂ loading was variedbetween 0-0.5. This apparatus mimics the gas-liquid contacting of packedcolumns typically used for gas absorption processes. As can be observedthe behaviour is consistent with the results predicted from modellingfor both CO₂ and SO₂. As the SO₂ concentration increases in thegas-phase the CO₂ absorption flux is slightly reduced. The selectivityfor SO₂ absorption is further confirmed by the fact that the SO₂ contentin the exiting gas stream was below the detection limit of the gasanalyser, even when the absorbent had the highest CO₂ loading of 0.5.Also the SO₂ absorption flux remains unchanged with increasing CO₂loading of the solvent. This demonstrates experimentally the basis ofthe invention. That is, even when exposed to a high concentration of CO₂in the gas stream (relative to SO₂) and the solvent is saturated withCO₂ (a CO₂ loading of 0.5 for MEA), the solvent remains selective forSO₂ and absorbs it at the same flux as when the solvent is CO₂ free.

As a result of the SO₂ degrading the performance of CO₂ capture, arestriction of existing PCC technology is that the SO₂ content of fluegas must be reduced to less than 10 ppmv before its application. Levelsbelow 10 ppm are normally not achieved in existing flue gasdesulfurisation plants and the use of an additional wash step is needed,adding significantly to the investment costs.

For countries such as Australia, where no FGD is applied, the SO₂content of flue gas poses a serious barrier to the use of PCCtechnology. In such locations FGD must first be installed before CO₂capture can be undertaken, significantly increasing the cost andtechnical complexity of the process. The most widely practiced FGDtechnology is based on the use of calcium carbonate slurries toeventually provide a saleable gypsum (calcium sulfate) product. Thistechnology is used in power stations and has a wide range of technologysuppliers (eg. Alstom, Babcock-Wilcox, Chiyoda). In some applications aregenerative solvent technology is used, providing a pure SO₂ product.CANSOLV Technologies Inc has developed an amine based technology forcombined removal of CO₂ and SO₂ (WO2006/136016). The process uses twodifferent amine based solvents in separate liquid loops which are heatintegrated in the separate solvent regeneration steps. The absorption ofSO₂ and CO₂ is performed in the same absorber.

There exists a need for a simple and low cost CO₂ capture technology orprocess that can tolerate the typical levels of SO₂ present in untreatedflue gas from sulfur containing combustion sources but also from fluegases exiting a typical flue gas desulfurisation process.

It is an object of the present invention to overcome or at leastalleviate one or more of the problems associated with the prior art.

Reference to any prior art in the specification is not, and should notbe taken as, an acknowledgment or any form of suggestion that this priorart forms part of the common general knowledge in Australia or any otherjurisdiction or that this prior art could reasonably be expected to beascertained, understood and regarded as relevant by a person skilled inthe art.

SUMMARY OF THE INVENTION

Accordingly, in one aspect the present invention provides a process forremoving CO₂ and a second acid gas from a gas stream including the stepsof

-   -   providing a gas stream containing CO₂ in the range of about 1 to        about 30 vol %, and a second acid gas to an absorption column,        the absorption column having at least separate first and second        sections, the gas stream being provided to the first section of        the column    -   providing an absorbent liquid for CO₂ and the second acid gas to        the second section to flow counter current to the gas stream,        the solvent passing through the second section and the first        section of the column with at least a portion of the solvent        being removed from the absorption column prior to the first        section,    -   passing the gas stream through the absorption column        preferentially absorbing the second acid gas into the solvent in        the first section of the absorption column before passing to the        second section of the absorption column where CO₂ is absorbed        into the solvent,    -   recovering gas depleted in CO₂ and the second acid gas from the        second section of the column.

An advantage of the invention is the ability for the same solvent to beused to strip both CO₂ and second acid gas from the gas stream.

Preferably, a liquid flow distributor exists between the second andfirst sections of the absorption column. In one embodiment, the liquidflow distributor prevents liquid from flowing directly between thesecond and first sections of the column. In this embodiment, all of thesolvent is removed from the first section and a further portion of thesolvent split from this stream and returned to the second section of theabsorption column.

Preferably CO₂ is present in the flue gas in the range of about 3 toabout 30 vol %, and most preferably in the range of about 8 to about 14vol %.

Preferably, the solvent stream entering the first section of the columnhas a CO₂ content of between about 0 and about 200% of the saturated CO₂content. More preferably, the CO₂ content is between about 30 and about150% of the saturated CO₂ content. Most preferably, the CO₂ content isbetween about 80 and about 120% of the saturated CO₂ content.

It is preferred that the solvent is an aqueous solution comprising anyaqueous amine, ammonia or mixture thereof. A non-limiting disclosure ofsuitable types of amines inludes: primary, secondary, tertiary,sterically hindered, acyclic, cyclic, mono and poly amines,alkanolamines and amino acids. The amino acids may contain sulfonic,carbonic and phosphonic acid groups. A non-limiting disclosure ofsuitable amine compounds includes: Monoethanolamine (MEA), piperazine(PZ), 2-amino-2-methyl-propanol (AMP), methyldiethanolamine (MDEA),diethanolamine (DEA), piperidine, 1-piperidinemethanol,2-piperidinemethanol, 3-piperidinemethanol, 4-piperidinemethanol,1-piperidineethanol, 2-piperidineethanol, 3-piperidineethanol,4-piperidineethanol, taurine, glycine, sarcosine.

In another embodiment of the invention, the liquid flow distributorbetween the first and second section allows liquid to flow directly fromthe second section to the first section but at a restricted flow ratecausing the liquid to hold up in the first section. A portion of thesolvent, preferably equivalent to the hold up, is removed from thecolumn and the remainder passes through the distributor to the firstsection of the column.

A further embodiment may involve a combination of the above embodimentsin which a solvent flow distributor allows some flow and a portion ofthe removed solvent is returned to the second section.

The solvent removed prior to the first section (i.e. after passingthrough the second section) is CO₂ rich but has not had contact with gasrich in the second acid gas and so has not absorbed much, if any of thesecond acid gas. This removed solvent stream is subsequently processedto remove the CO₂ before being returned to the absorption column.

As the second acid gas is absorbed into the solvent in the first sectionthe solvent being removed from the first section of the column is richin the second acid. This solvent stream may subsequently be processed toremove the second acid gas and then returned to the absorption column.

Preferably the second acid gas is selected from the group of SO₂, H₂S,HF, HCl and NO₂. The second acid gas is more preferably a sulfurous acidgas such as SO₂ and H₂S and most preferably SO₂.

It is preferred that when the second acid gas is SO₂, and that the SO₂is present in the flue gas in the range of about 1 to about 100,000 ppm,more preferably in the range of about 1 to about 10,000 ppm, and mostpreferably in the range of about 1 to about 1,000 ppm.

In another aspect of the invention, there is provided an absorptioncolumn for separating CO₂ and a second acid gas from a gas stream, thecolumn comprising

-   -   a first and second section for the absorption of CO₂ and the        second acid gas;    -   a solvent inlet in the second section for the addition of a        absorbent liquid for CO₂ and the second acid gas;    -   a gas inlet in the first section for the addition of a CO₂ and        the second acid gas containing gas stream;    -   a gas outlet from the second section of the column;    -   a first solvent outlet for the removal of at least a portion of        the solvent from the second section of the column and a second        solvent outlet from the first section of the column; and    -   a liquid flow distributor arrangement to allow a portion of the        solvent to flow from the second section of the column to the        first section.

In a preferred form of this aspect of the invention, the flowdistributor arrangement comprises a flow restrictor which allows arestricted flow of solvent from the second section to the first sectionwhile gas is able to continue up the column between the sections. Theflow restrictor may be a simple orifice or perforated plate whichprevents all of the solvent flowing down the column to flow directlyinto the first section or the column. The difference between the solventflowing through the second section and that entering the first isremoved through the first solvent outlet. The flow distributor mightalso be derived from sieve trays, bubble cap trays or valve trays whichare commonly used in gas/liquid contactors. These tray designs can bemodified to ensure that the desired liquid flow distribution isachieved.

Alternatively the flow distributor arrangement prevents all of thesolvent from flowing directly from the second section to the firstsection while allowing gas to pass through. The solvent is removed fromthe second section and a stream including a portion of the solventdiverted to the first section of the column.

In a further preferred aspect, the first section of the apparatus alsoacts as a quench to cool the flue gas from an initial temperature in therange of about 80 to about 180° C., to a lower temperature in the rangeof about 20 to about 60° C. It is preferred that the initial temperatureis in the range of about 80 to about 120° C.; and most preferably thetemperature is about 80° C. It is preferred that quench cools the fluegas to a temperature in the range of about 30 to about 50° C.; and mostpreferably to a temperature of about 40° C.

The solvent removed prior to the first section is CO₂ rich but has nothad contact with gas rich in the second acid gas and so has not absorbedmuch, if any of the second acid gas. This removed solvent stream issubsequently passed to a CO₂ regeneration unit where the solvent isprocessed to remove the CO₂ before being returned to the absorptioncolumn.

As the second acid gas is absorbed into the solvent in the first sectionand CO₂ desorbed, the solvent being removed from the first section ofthe column is rich in the second acid gas and CO₂ lean. This solventstream may subsequently pass to a recovery unit for the second acid gaswhere the solvent is processed to remove the second acid gas and thenreturned to the absorption column.

Preferably the second acid gas used in the apparatus is selected fromthe group of SO₂, H₂S, HF, HCl and NO₂. The second acid gas is morepreferably a sulfurous acid gas such as SO₂ and H₂S and most preferablySO₂.

As used herein, except where the context requires otherwise, the term“comprise” and variations of the term, such as “comprising”, “comprises”and “comprised”, are not intended to exclude further additives,components, integers or steps.

BRIEF DESCRIPTION OF THE DRAWINGS/FIGURES

FIG. 1 is a graph showing the impact of gas phase SO₂ concentration onthe CO₂ absorption flux into a thin film of 30% w/w aqueous MEA at 40°C. as determined by modelling; and

FIG. 2 is a graph showing the impact of gas phase SO₂ concentration onthe CO₂ absorption flux into a thin film of 30% w/w aqueous MEA at 40°C. as determined by experiment; and

FIG. 3 is an illustration of the wetted-wall contactor used toexperimentally determine the CO₂ and SO₂ absorption flux into a fallingthin liquid film of 30% w/w MEA; and

FIG. 4 is a schematic diagram of an embodiment of the invention whichwould allow CO₂ and SO₂ removal from a single absorber column and singlesolvent stream.

DETAILED DESCRIPTION OF THE EMBODIMENTS

While the invention will be described with reference to CO₂ and SO₂gases, it is intended that the invention is equally applicable to CO₂ inthe presence of a second acid gas where the acid formed is a strongeracid than that formed from CO₂. These include SO₂, H₂S, NO₂, HF and HCl.

The present invention is a process that allows both CO₂ and SO₂ removalfrom a gas stream using a single absorber tower and single aqueoussolvent. The invention utilises the differences in physical solubility,absorption rate and acidity of CO₂ and SO₂ to achieve this.

A schematic diagram of the process is shown in FIG. 4. Flue gas (2)enters at the bottom of a packed absorber column (1). The design of thecolumn (1) itself may be similar in design to those in existing use forgas treating processes.

The absorption column (1) for separating CO₂ and a second acid gas froma gas stream, the column includes a first and second section (4, 5) forthe absorption of CO₂ and the second acid gas and a liquid flowdistributor (8). The second section (5) includes a solvent inlet (20)for the addition of liquid stream (3) including an absorbent liquid forCO₂ and the second acid gas, a gas outlet (15) and a first solventoutlet for the removal of at least a portion of the solvent as stream(6) from the second section (5) of the column.

First section (4) includes a gas inlet (21) for the addition of a gasstream (2) containing CO₂ and the second acid gas and a second solventoutlet (23) for solvent stream (11) from the first section of thecolumn. The liquid flow distributor arrangement (8) is provided with aliquid distributor to allow a portion of the solvent to flow from thesecond section of the column to the first section.

An aqueous solvent, suitable for CO₂ capture such as but not limited toan aqueous amine, lean in CO₂ and SO₂ enters at the top of the absorbercolumn (liquid stream 3). As the gas stream moves up the column SO₂absorption occurs in the bottom first section (4). This first section(4) of column (1) may also act as a quench to cool the flue gas to atemperature suitable for CO₂ capture (˜40° C.) from its originaltemperature (normally above 80° C.). This first section (4) of column(1) is exposed to a stream (7) of absorbent liquid. Stream (7) is a sidestream comprising a small portion of the solvent stream (6). Solventstream (6) is the result of contact with the gas stream in top secondsection (5) of the absorption column, now CO₂ rich, which originallyentered at the top of the absorber as solvent stream (3). Even thoughthe solvent is CO₂ rich effective SO₂ removal still occurs in firstsection (4) due to the selectivity for SO₂. Some CO₂ desorption may alsooccur at this point increasing the CO₂ content of the gas stream. TheSO₂ lean gas stream then moves into the mid and upper second sections(5) of the column.

In mid and upper second sections (5) of the column CO₂ absorption occursas in a traditional CO₂ capture process. At the interface between thesecond section (5) of the column and the bottom section, a flowdistributor arrangement (8) is shown which allows gas to continue torise up the column while restricting the flow of solvent down thecolumn. The solvent progressing down the column (1) after passingthrough the second section (5) is the now CO₂ rich and the SO₂ leansolvent. This solvent at the base (9) of the second section is removedand a return stream (7) which is a small portion of stream (6) returnedto the first section of the column (1).

The flow distributor arrangement (8) may also take the form of arestrictor such as a sieve plate or orifice (not shown) which allows gasto pass upwardly in the column from the first section (4) to the secondsection (5) while allowing a small amount of solvent to continue downthe column (1). The flow restrictor causes a hold up in the solvent atthe base of the second section equivalent to the difference to thesolvent flow through the second and first sections (5, 4) which isremoved from the column 1 in a stream similar to stream 6.

Solvent stream 6 then passes to a CO₂ regeneration unit (10) for CO₂stripping and solvent regeneration.

As mentioned above, a portion of the solvent which has passed throughthe second section (5) of the column passes into the bottom firstsection (4) of the column where SO₂ removal occurs. The fraction of theremainder of the total process liquid stream 3 needed to provide bulkcapture of SO₂ will depend on the ratio of SO₂/CO₂ content in the fluegases and typically will range between 0.1% and 3% of the total processstream needed for CO₂ capture. Given this much reduced flow, it may bedesirable to recirculate the solvent in the first section (4) multipletimes in the first section (4) of the column to provide adequatecontact. Alternatively a dedicated gas/liquid contactor able to operateat high gas/liquid ratios, such as a membrane contactor, might be used.

The fraction of the process stream (6) used for selective SO₂ absorptionmight also be obtained as a product stream from a separation step, whichwill result in partial rejection of amines, thus preventing them fromentering the bottom part of the absorber. This will avoid excessiveoxidation in the bottom (SO₂-removal) stage of the absorber. The SO₂rich solvent (11) from the first section (4) of the column is thenremoved and passed to an SO₂ regeneration unit (12) for sulfur recoveryand solvent regeneration. The regenerated solvent streams (13, 14) arethen mixed and returned to the top of the absorber as process stream(3).

In an alternative embodiment (not shown), at least a portion of the SO₂rich solvent stream (11) may be recycled and added to the top of firstsection (4) with solvent stream (7). The recycle of the SO₂ rich solventstream (11) potentially will provide some cost and performance benefits,by increasing the concentration of SO₂ in solvent stream (11).

CO₂ stripping and solvent regeneration for the CO₂ rich and SO₂ leansolvent stream carried out in CO₂ regeneration unit (10) uses a standardCO₂ stripping process. A general description of a CO₂ stripping processfollows, however this does not preclude the use of any other CO₂stripping process. The solvent stream exiting the absorber is preheated(generally via a heat exchange with the lean CO₂ solvent stream from thestripper bottom) and enters the top of a packed column. At the base ofthe column liquid is heated to 120-160° C. via a reboiler to generatestripping steam and heat the solvent. The solvent entering at the top ofthe column is contacted with and heated by the stripping steam. At thiselevated temperature, the CO₂ absorption process is reversed and CO₂comes out of solution. The gaseous CO₂ stream passes upwards through thecolumn and exits through the top for further purification andcompression for transport. The CO₂ lean solvent stream is removed fromthe bottom of the column, cooled via heat exchange, and returned to theabsorber.

Sulfur recovery and solvent regeneration of the SO₂ rich stream (11) maybe carried out using a sulfur recovery process suitable for use withaqueous amines. Due to oxidation of sulfite species as a result of thepresence of oxygen in the flue gas both sulfites and sulfates may bepresent in this stream. Options include but are not limited to:metathesis via the addition of NaOH/NaCO₃ or other hydroxides/carbonatesto form Na₂SO_(3(s)) and Na₂SO_(4(s)) precipitates or others; ionexchange resins to separate sulfites and sulfates from other species;and membrane electrodialysis to separate sulfites and sulfates fromother species. The sulfur recovery step might also beneficially beintegrated with the amine reclaimer. The reclaimer might be adistillation column in which the amine is recovered as the overheadproduct as a result of its higher volatility. Degradation products, heatstable salts, including sulfur products will then be left in the bottomfraction of the distillation column. Alternatively, as is the case fornon-volatile amines, the amine reclaimer might be based on the removalof degradation products and heat stable salts via a combination ofelectrodialysis, filtration, adsorption and ion-exchange. These stepscan also be used to remove the sulfur products.

The present invention provides an improved CO₂ capture process for SO₂containing flue gas streams that does not require SO₂ removal (FGD)prior to its application. It also utilises existing process technologiesalready in use for gas cleaning applications. The ability to carry outCO₂ capture in the presence of SO₂ is extremely desirable from anindustrial perspective as it eliminates the need to install FGDequipment (where it is not already installed) to allow a CO₂ captureprocess to be used. In situations where FGD is installed it avoids theinstallation of additional capacity in existing columns or the use of anadditional clean-up step using an additional column. This hassignificant benefits in terms of reducing cost and the overall technicalcomplexity of applying CCS to flue gas streams that contain SO₂.

It will be understood that the invention disclosed and defined in thisspecification extends to all alternative combinations of two or more ofthe individual features mentioned or evident from the text or drawings.All of these different combinations constitute various alternativeaspects of the invention.

1. A process for removing CO₂ and a second acid gas from a gas streamincluding the steps of providing a gas stream containing CO₂ in therange of about 1 to about 30 vol %, and a second acid gas to anabsorption column, the absorption column having at least separate firstand second sections, the gas stream being provided to the first sectionof the column providing an absorbent liquid for CO₂ and the second acidgas to the second section to flow counter current to the gas stream, thesolvent passing through the second section and the first section of thecolumn with at least a portion of the solvent being removed from theabsorption column prior to the first section, passing the gas streamthrough the absorption column preferentially absorbing the second acidgas into the solvent in the first section of the absorption columnbefore passing to the second section of the absorption column where CO₂is absorbed into the solvent, recovering gas depleted in CO₂ and thesecond acid gas from the second section of the column.
 2. The process ofclaim 1 wherein a liquid flow distributor prevents liquid from flowingdirectly between the second and first sections of the column whileallowing gas to pass through, all of the solvent being removed from thefirst section and a further portion of the solvent split from thisstream and returned to the second section of the absorption column. 3.The process of claim 1 wherein a liquid flow distributor between thefirst and second section allows liquid to flow directly from the secondsection to the first section and a portion of the solvent is removedfrom the column prior to entering the first section of the column. 4.The process of claim 1 wherein the solvent removed prior to the firstsection is subsequently processed to remove the CO₂ before beingreturned to the absorption column.
 5. The process of claim 1 wherein thesolvent removed from the first section of the column is subsequentlyprocessed to remove the second acid gas and then returned to theabsorption column.
 6. The process of claim 1 wherein at least a portionof the solvent removed from the first section of the column is recycledto the top of the first section.
 7. The process of claim 1 wherein thesecond acid gas is selected from the group of SO₂, H₂S, HF, HCl and NO₂.8-11. (canceled)
 12. The process of claim 1 wherein the gas streamcontains CO₂ in the range of about 3 to about 30 vol %.
 13. (canceled)14. The process of claim 1 wherein the solvent stream entering the firstsection of the column has a CO₂ content of between about 0 and about200% of the saturated CO₂ content.
 15. (canceled)
 16. (canceled)
 17. Anabsorption column for separating CO₂ and a second acid gas from a gasstream, the column comprising a first and second section for theabsorption of CO₂ and the second acid gas; a solvent inlet in the secondsection for the addition of an absorbent liquid for CO₂ and the secondacid gas; a gas inlet in the first section for the addition of a gasstream containing CO₂ and the second acid gas; a gas outlet in thesecond section of the column; a first solvent outlet for the removal ofat least a portion of the solvent from the second section of the columnand a second solvent outlet from the first section of the column; and aliquid flow distributor arrangement to allow a portion of the solvent toflow from the second section of the column to the first section.
 18. Theapparatus of claim 17 wherein the flow distributor arrangement preventsall of the solvent from flowing directly from the second section to thefirst section while allowing gas to pass through, the solvent beingremoved from the second section and a stream including a portion of thesolvent which is diverted to the first section of the column.
 19. Theapparatus of claim 17 wherein the flow distributor arrangement comprisesa flow restrictor which allows a restricted flow of solvent directlyfrom the second section to the first section while gas is able tocontinue up the column between the sections, the difference in flowbetween the solvent flowing through the second section and that enteringthe first being removed through the first solvent outlet.
 20. Theapparatus of claim 17 wherein the solvent removed from the secondsection is subsequently passed to a CO₂ regeneration unit where thesolvent is processed to remove the CO₂ before being returned to theabsorption column.
 21. The apparatus of claim 17 wherein the solventremoved from the first section of the column is subsequently passed toan acid gas recovery unit for the second acid gas where the solvent isprocessed to remove the second acid gas component and then returned tothe absorption column.
 22. The apparatus of claim 17 wherein at least aportion of the solvent removed from the first section of the column isrecycled to the top of the first section.
 23. The apparatus of claim 17wherein the second acid gas is selected from the group of SO₂, H₂S, HF,HCl and NO₂. 24-27. (canceled)
 28. The apparatus of claim 17 where thefirst section also acts as a quench to cool the flue gas from an initialtemperature of about 80 to about 180° C., to a temperature of 20-60° C.29. The apparatus of claim 28 wherein the flue gas is cooled to atemperature of about 30 to about 50° C.
 30. The apparatus of claim 28wherein the flue gas is cooled to a temperature of about 40° C.
 31. Theapparatus of claim 17 wherein the second section is above the firstsection.